State of the Art; Drill bits for drilling oil, gas, and geothermal wells, and other similar uses typically comprise a solid metal or composite matrix-type metal body having a lower cutting face region and an upper shank region for connection to the bottom hole assembly of a drill string formed of conventional jointed tubular members which are then rotated as a single unit by a rotary table or top drive drilling rig, or by a downhole motor selectively in combination with the surface equipment. Alternatively, rotary drill bits may be attached to a bottom hole assembly, including a downhole motor assembly, which is in turn connected to an essentially continuous tubing, also referred to as coiled, or reeled, tubing wherein the downhole motor assembly rotates the drill bit. The bit body may have one or more internal passages for introducing drilling fluid, or mud, to the cutting face of the drill bit to cool cutters provided thereon and to facilitate formation chip and formation fines removal. The sides of the drill bit typically may include a plurality of radially or laterally extending blades that have an outermost surface of a substantially constant diameter and generally parallel to the central longitudinal axis of the drill bit, commonly known as gage pads. The gage pads generally contact the wall of the borehole being drilled in order to support and provide guidance to the drill bit as it advances along, a desired cutting path, or trajectory.
As known within the art, blades provided on a rotary drill bit may be selected to be provided with replaceable cutting elements installed thereon, allowing the cutting elements to engage the formation being drilled and to assist in providing cutting action therealong. Replaceable cutters may also be placed adjacent to the gage area of the rotary drill bit and sometimes on the gage thereof. One type of cutting element, referred to as inserts, compacts, and cutters, has been known and used for providing the primary cutting action of rotary drill bits and drilling tools. These cutting elements are typically manufactured by forming a superabrasive layer, or table, upon a sintered tungsten carbide substrate. As an example, a tungsten carbide substrate having a polycrystalline diamond table or cutting face is sintered onto the substrate under high pressure and temperature, typically about 1450° C. to about 1600° C. and about 50 to about 70 kilobar pressure to form a PDC cutting element or PDC cutter. During this process, a metal sintering aid or catalyst such as cobalt may be premixed with the powdered diamond or swept from the substrate into the diamond to form a bonding matrix at the interface between the diamond and substrate.
Further, in one conventional approach to enlarge a subterranean borehole, it is known to employ both eccentric and bicenter bits to enlarge a borehole below a tight or undersized portion thereof. For example, an eccentric bit includes an extended or enlarged cutting portion which, when the bit is rotated about its axis, produces an enlarged borehole. An example of an eccentric bit is disclosed in U.S. Pat. No. 4,635,738, assigned to the assignee of the present invention. Similarly, a bicenter bit assembly employs two longitudinally superimposed bit sections with laterally offset axes. An example of an exemplary bicenter bit is disclosed in U.S. Pat. No. 5,957,223, also assigned to the assignee of the present invention. The first axis is the center of the pass-through diameter, that is, the diameter of the smallest borehole the bit will pass through. Accordingly, this axis may be referred to as the pass-through axis. The second axis is the axis of the hole cut in the subterranean formation as the bit is rotated and may be referred to as the drilling axis. There is usually a first, lower and smaller diameter pilot section employed to commence the drilling, and rotation of the bit is centered about the drilling axis as the second, upper and larger diameter main bit section engages the formation to enlarge the borehole, the rotational axis of the bit assembly rapidly transitioning from the pass-through axis to the drilling axis when the full diameter, enlarged borehole is drilled.
In another conventional approach to enlarge a subterranean borehole, rather than employing a one-piece drilling structure such as an eccentric bit or a bicenter bit to enlarge a borehole below a constricted or reduced-diameter segment, it is also known to employ an extended bottom hole assembly (extended bicenter assembly) with a pilot drill bit at the distal end thereof and a reamer assembly some distance above. This arrangement permits the use of any standard rotary drill bit type, be it a rock bit or a drag bit, as the pilot bit, and the extended nature of the assembly permits greater flexibility when passing through tight spots in the borehole as well as the opportunity to effectively stabilize the pilot drill bit so that the pilot hole and the following reamer will traverse the path intended for the borehole. This aspect of an extended bottom hole assembly is particularly significant in directional drilling.
The assignee of the present invention has, to this end, designed as reaming structures so-called “reamer wings,” which structures generally comprise a tubular body having a fishing neck with a threaded connection at the top thereof and a tong die surface at the bottom thereof, also with a threaded connection. U.S. Pat. Nos. 5,497,842 and 5,495,899, both assigned to the assignee of the present invention, disclose reaming structures including reamer wings. The upper midportion of the reamer wing tool includes one or more longitudinally extending blades projecting generally radially outwardly from the tubular body, the outer edges of the blades carrying PDC cutting elements. The midportion of the reamer wing also may include a stabilizing pad having an arcuate exterior surface having a radius that is the same as or slightly smaller than the radius of the pilot hole on the exterior of the tubular body and longitudinally below the blades. The stabilizer pad is characteristically placed on the opposite side of the body with respect to the reamer blades so that the reamer wing tool will ride on the pad due to the resultant force vector generated by the cutting of the blade or blades as the enlarged borehole is cut. U.S. Pat. No. 5,765,653, assigned to the assignee of the present invention, discloses the use of one or more eccentric stabilizers placed within or above the bottom hole reaming assembly to permit ready passage thereof through the pilot hole or pass-through diameter, while effectively radially stabilizing the assembly during the hole-opening operation thereafter.
Conventional expandable reamers may include blades pivotably or hingedly affixed to a tubular body and actuated by way of a piston disposed therein as disclosed by U.S. Pat. No. 5,402,856 to Warren. In addition, U.S. Pat. No. 6,360,831 to Åkesson et al. discloses a conventional borehole opener comprising a body equipped with at least two hole-opening arms having cutting means that may be moved from a position of rest in the body to an active position by way of a face thereof that is directly subjected to the pressure of the drilling fluid flowing through the body. However, the face, being directly exposed to the drilling fluid, may be subjected adversely to erosion or chemical effects caused thereby.
Notwithstanding the prior approaches to drill and/or ream a larger-diameter borehole below a smaller-diameter borehole, the need exists for improved apparatus and methods for doing so. For instance, bicenter and reamer wing assemblies are limited in the sense that the pass-through diameter is nonadjustable and limited by the reaming diameter. Further, conventional reaming assemblies may be subject to damage when passing through a smaller diameter borehole or casing section.